Liquids can accumulate in gaseous wells (e.g., natural gas wells and gassy oil wells) and can create backpressure on the formation, which slows further production of hydrocarbons. To increase the inflow of hydrocarbons into the wellbore, the liquids must be removed so that the backpressure on the formation can be reduced. A number of technologies for dealing with liquid accumulation are used in the art.
To help explain liquid accumulation, the lift system 10 in FIG. 1 has production tubing 30 deployed in a casing 22 of a wellbore 20 for a natural gas well. The casing 22 has perforations 24 so that the natural gas well produces gas and liquid, such as water and hydrocarbon, from the reservoir, and a production tubing packer 32 isolates the casing annulus from the formation fluid (gas G and liquids L). The production tubing 30 conveys the produced fluid to the wellhead 12 at the surface. As is known, the production rate of the natural gas well is a function of the pressure differential between the underground reservoir and the wellhead 12. As long as the pressure differential creates a critical velocity (i.e., sufficient gas flow velocity or gas flow rate to displace the liquids) in the well, then the produced fluid (gas G and liquid L) can be lifted through the production tubing 30 to surface.
Unfortunately, the pressure differential decreases when the reservoir pressure declines over time and when backpressure in the well acts against the reservoir pressure. As natural gas G and associated liquids L are extracted during production, the gradual loss of the reservoir pressure occurs in some natural gas wells, thus decreasing the pressure differential. Additionally, the produced liquids, such as water and hydrocarbon, can tend to accumulate in the wellbore 20 and reduce the well's production rate, as noted previously.
Unaided removal of these produced liquids L depends on the velocity of the gas stream produced from the formation. As the reservoir pressure and the flow potential decreases in the well, a corresponding drop occurs in the flow velocity of the natural gas G through the production tubing 30 to the wellhead 12. Eventually, the flow velocity becomes insufficient to lift the liquids L so that a column of liquids L accumulates in the wellbore 20. This liquid loading phenomenon decreases the production of the well because the weight of the fluid column above the producing formation produces additional backpressure on the reservoir.
Various “dewatering” techniques can be used to deal with liquid accumulation. For example, mechanical pumps can pump the accumulated liquid L to the surface, but mechanical pumps are typically inefficient in gassy wells. One efficient dewatering technique for a gas well is to increase flow velocity to above critical velocity by decreasing the cross-sectional area through which the fluids must flow. Reduced flow area allows the flowing fluid pressure to increase, thereby increasing the difference between the pressure in the wellbore 20 and the pressure of the surface flow line 19. This increase in pressure differential results in increased flow velocity.
One method of increasing velocity by reducing flow area is by using a small-diameter tubing string run inside the production tubing 30 of the well. This “velocity string” 40 can be deployed from a coiled tubing reel 14 through an injector 16 on the wellhead 12 and into the production tubing 30. The flow of produced fluid may be up the smaller internal diameter 45 of the velocity tube 40.
Another method of increasing velocity by reducing flow area is to use the inserted string 40 as dead space to reduce the flow area within the production tubing 30. Disposed in the production tubing 30, this “dead string” 40 produces an annular flow path in the micro-annulus 35 (i.e., the space between the outside of the velocity string 40 and the inside of the production tubing 30). As shown in FIG. 1, produced fluids pass from the formation into the wellbore 20 through the perforations 24 and can be lifted to the surface by the fluid velocity through the micro-annulus 35.
The string 40 (whether used as a “velocity string” or a “dead string”) must be configured to produce flow velocities higher than critical velocity while minimizing flow restrictions beyond that which is necessary to achieve critical velocity. Therefore, the string 40 can quickly become ineffective as gas flow declines. In particular, the reservoir pressure in the gas well can eventually be depleted over time to the point where there may be insufficient velocity to transport all liquids from the wellbore 20 to the surface. Although gas can be injected from the surface to help increase the velocity of produced gas, the injected gas adds to the backpressure downhole and potentially can retard inflow of well fluids into the wellbore 20.
In another technique, operators can inject surfactant into the wellbore 20. Typically, the foam is dispersed near the perforated section at the casing's perforations 24. The surfactant reacts with water to reduce the water's surface tension so it foams in the presence of turbulence, thereby reducing the apparent liquid density of the water and reducing the critical velocity needed to lift the water from the system 10.
For vertical wells, many of the conventional lift systems can be used to increase gas production, but such conventional systems are less effective in the horizontal sections of wells. For example, horizontal wells may often have more than one relative low spot where liquids can pool so that dealing with the pooled liquids in horizontal wells can be particularly problematic. A mechanical pump is limited to suction at one point in the wellbore and cannot realistically address multiple low spots that may be present in horizontal wells. Although injecting foam surfactant in a vertical wellbore can be relatively straightforward, dispensing the foam surfactant at correct concentrations into multiple low spots of a horizontal wellbore can be challenging and expensive. Finally, a velocity string deployed in production tubing of a horizontal wellbore can quickly become ineffective as well pressures decline, especially when used in shale gas wells having steep declining curves.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.